Integration methods of gas processing plant and nitrogen rejection unit for high nitrogen feed gases

ABSTRACT

Gas processing plants and methods are contemplated in CO 2  is effectively removed to very low levels from a feed gas to an NRU unit by adding a physical solvent unit that uses waste nitrogen produced by the NRU as stripping gas to produce an ultra-lean solvent, which is then used to treat the feed gas to the NRU unit. Most preferably, the physical solvent unit includes a flash unit and stripper column to produce the ultra-lean solvent.

This application claims priority to U.S. provisional application withthe Ser. No. 61/717,926, filed 24 Oct. 2012, and incorporated byreference herein.

FIELD OF THE INVENTION

The field of the invention is gas processing, and especially processinghydrocarbonaceous feed gas with high nitrogen (N₂) content to produce alow CO₂ content feed gas (≦1000 ppm) to a nitrogen rejection unit (NRU),particularly in retrofitting existing gas treating units.

BACKGROUND OF THE INVENTION

Because of the high value of condensate and liquids, oil and gas fieldsare often injected with nitrogen to increase oil and gas production. Asa consequence, the nitrogen content in the feed gas to a downstream gasprocessing plant from such fields will increase over time. For example,in the initial phase of the gas processing plant operation, nitrogencontent in the feed gas from the field is typically low (e.g., 1-3 mol%). As enhanced oil recovery process continues, the nitrogen content inthe feed gas to the gas plant can significantly increase (e.g., to ashigh as 18-30 mol %), which in most cases necessitates the use of anitrogen rejection unit to remove the nitrogen from processed gas tomeet pipeline transmission specification (e.g., typically 3 mol %).

In addition to nitrogen removal, CO₂ is also present in most feed gasstreams from a gas well and must be removed by an acid gas removal unit(e.g., to 1-2 mol %) to avoid CO₂ freezing in a downstream demethanizercolumn in which natural gas liquids are recovered from the feed gas. CO₂removal is typically performed using an amine unit and produces in mostcases a feed stream to a downstream natural gas recovery unit (NGLrecovery unit) that will have sufficiently low CO₂ content to avoidfreezing issues in the NGL recovery unit (e.g., operating at about −150°F. to remove C2+ components). However, a typical NRU operates at a muchlower temperatures (e.g., as low as −250° F.), and at such low cryogenictemperatures, the NRU feed gas must contain no more than 0.001 to 0.002mol % (200 to 2000 ppmv) CO₂. Unfortunately, such low levels arecommonly not achievable with the amine units of most existing gasprocessing plants as these units are designed for production of a feedgas to an NGL recovery unit, but not for deep CO₂ removal. Thus, in manycases an acid gas removal unit must be revamped for deep CO₂ to meet theNRU feed gas specification as exemplarily depicted in Prior Art FIG. 1,described in more detail below.

An amine unit revamp option typically requires increasing solventcirculation and heating duties, and changing out the existing solventwith a more aggressive amine solvent such as DGA (Diglycolamine) oractivated MDEA (Methyl Diethanolamine). While such option is at leastconceptually possible, capital requirements and operating costs areoften very high and require extended plant shutdown, which is generallynot desirable. Moreover, most amine plants already operate at maximumcapacity and do not have room for further solvent increase.Alternatively, a new amine unit can be added downstream of the NGLrecovery unit as exemplarily depicted in Prior Art FIG. 2, and describedin more detail below. While additional units are less intrusive than arevamp option, new amine units typically produce a wet treated gas thatmust be further dried with molecular sieve or other dryers to avoidfreezing in the NRU, making this option even more costly.

Nitrogen rejection, CO₂ removal, and NGL recovery can be performed in anintegrated process having multiple process streams and as fractionationsteps as is described, for example, in GB 2500830 or WO 2012/177405.These and all other referenced extrinsic materials are incorporatedherein by reference in their entirety. Where a definition or use of aterm in a reference that is incorporated by reference is inconsistent orcontrary to the definition of that term provided herein, the definitionof that term provided herein is deemed to be controlling. In anotherapproach, CO₂ freezing can be entirely avoided by use of a solventprocess as described in U.S. Pat. No. 5,406,802 or US 2002/0139244.While such known systems and methods are generally effective for theirintended purpose, they will require in most cases de novo installationsand will not be suitable for revamps.

Thus, although various configurations and methods are known to rejectnitrogen from the feed gas, all or almost all suffer from one or moredisadvantages. Among other things, feed gas to the NRU from an upstreamCO₂ removal unit will often have a CO₂ content that is unsuitable forfeeding into an NRU, or to achieve low CO₂ levels, existing amine unitshave to be modified or additional amine units must be installed. Viewedfrom a different perspective, sufficient CO₂ removal by an existingamine (or other CO₂ removal) unit is not provided or too expensive foreconomic implementation into a plant with the existing amine (or otherCO₂ removal) unit. Moreover, where additional amine units are provided,the treated gas is frequently too wet for direct feeding into the NRUand must be dried. Thus, there is still a need to provide improvedmethods and configurations for CO₂ removal in high nitrogen feed gases.

SUMMARY OF THE INVENTION

The inventor has unexpectedly discovered that deep CO₂ removal from anNRU feed gas can be achieved by use of an ultra-lean physical solventthat is formed by flashing and stripping with a nitrogen reject streamfrom the NRU. Thusly treated gas will have a residual CO₂ content of5000 ppmv or lower, more typically 3000 ppmv or lower, even moretypically 2000 ppmv or lower, or even 1000 ppmv or lower and so meetsthe feed gas specification of the NRU.

Most preferably, contemplated physical solvent (e.g., propylenecarbonate) regeneration methods use flash regeneration and do notrequire heating. Moreover, as the physical solvent is in most cases anon-aqueous solvent and operates under a dry environment, production ofa dry overhead gas from the solvent absorber is achieved. Notably, suchadvantage is also realized by use of the dry nitrogen reject (waste)stream from the NRU as the stripping gas for the flashed physicalsolvent. Therefore, no dehydration of the product gas is required. Incontrast, atypical amine using uses an aqueous solvent resulting in awet gas leaving the amine unit.

In one aspect of the inventive subject matter, a gas treatment plant fortreatment of a CO₂-and N2-containing feed gas includes a primary CO₂removal unit that receives a feed gas from a feed gas source and thatremoves from the feed gas CO₂ to a first concentration to so form atreated feed gas. A secondary CO₂ removal unit is fluidly coupled to theprimary CO₂ removal unit, receives the treated feed gas, and uses anultra-lean solvent in an absorber to produce a CO₂-loaded solvent and aCO₂-depleted feed gas having residual CO₂ at a second concentration.Contemplated gas treatment plants will further comprise or be coupled toa nitrogen rejection unit that removes N₂ from the CO₂-depleted feed gasand produces a N₂ waste stream and a pipeline gas, wherein the secondaryCO₂ removal unit comprises a flash unit and a stripping column fluidlycoupled to the absorber. The flash unit is used to flash the CO₂-loadedsolvent and to produce a flashed solvent, while the stripping columnuses the N₂ waste stream as a stripping gas for the flashed solvent tothereby produce the ultra-lean solvent. As used herein, and unless thecontext dictates otherwise, the term “coupled to” is intended to includeboth direct coupling (in which two elements that are coupled to eachother contact each other) and indirect coupling (in which at least oneadditional element is located between the two elements). Therefore, theterms “coupled to” and “coupled with” are used synonymously.

In some aspects of the inventive subject matter the feed gas source is ahydrocarbon production well and that delivers a feed gas with a N₂concentration of at least 10 mol % and a CO₂ concentration of at least 2mol %. In most cases, the feed gas pressure is relatively high (e.g., atleast 500 psig, or at least 700 psig, or at least 1000 psig), theprimary CO₂ removal unit operates with an amine absorber and aminesolvent regenerator, and/or the flash unit in the secondary CO₂ removalunit is operated such that the flashed solvent has a pressure of equalor less than 100 psig (e.g., which may be accomplished via a hydraulicturbine). Where desired, it is contemplated that the secondary CO₂removal unit further comprises a compressor that increases pressure ofthe N₂ waste stream prior to delivery of the N₂ waste stream to thestripping column.

In other aspects of the inventive subject matter, the primary CO₂removal unit is configured such that the treated feed gas has a CO₂concentration of between 1-5 mol %, and the secondary CO₂ removal unitis configured such that the CO₂-depleted feed gas has a CO₂concentration of equal to or less than 3,000 ppmv CO₂, and morepreferably equal to or less than 1,000 ppmv CO₂.

Therefore, the inventor also contemplates a method of processing a CO₂and N₂-containing feed gas (typically a hydrocarbonaceous feed gas) thatincludes a step of removing in a primary CO₂ removal unit CO₂ from thefeed gas to a first CO₂ concentration to thereby form a treated feedgas, and a further step of using an ultra-lean solvent in a secondaryCO₂ removal unit to further remove CO₂ from the treated feed gas tothereby produce a CO₂-loaded solvent and a CO₂-depleted feed gas havinga second CO₂ concentration. In another step, N₂ is removed from theCO₂-depleted feed gas in a nitrogen rejection unit to so produce a N₂waste stream and a pipeline gas, and a portion of the N₂ waste stream isthen used as a stripping gas in the secondary CO₂ removal unit tothereby produce the ultra-lean solvent from the CO₂-loaded solvent.

In preferred aspects, the step of removing CO₂ in the primary CO₂removal unit involves contacting the feed gas with an amine solvent,and/or the ultra-lean solvent in the secondary CO₂ removal unit is aphysical solvent (e.g., propylene carbonate). While not limiting to theinventive subject matter, it is also contemplated that CO₂ is flashedfrom the CO₂-loaded solvent prior to the step of using the N₂ wastestream as a stripping gas. In most cases, it is contemplated that thefirst CO₂ concentration is between 1-5 mol %, and that the second CO₂concentration equal to or less than 3,000 ppmv, and more preferablyequal to or less than 1,000 ppmv.

Viewed from a different perspective, the inventors therefore alsocontemplate a method of regenerating an ultra-lean solvent for deep CO₂removal of a treated feed gas (that typically has equal or less than 2mol % CO₂) that includes a step of using an ultra-lean physical solvent(preferably a non-aqueous physical solvent) in an absorber to remove CO₂from the treated feed gas to thereby form a CO₂-loaded solvent and aCO₂-depleted feed gas, and a further step of removing in a nitrogenrejection unit N₂ from the CO₂-depleted feed gas (with typically equalor less than 3,000 ppmv CO₂) to thereby produce a N₂ waste stream and apipeline gas. In yet another step, the ultra-lean physical solvent isregenerated from the CO₂-loaded solvent in a process that includesflashing the CO₂-loaded solvent (e.g., reduction of pressure of theCO₂-loaded solvent by at least 1,000 psig) and stripping the flashedCO₂-loaded solvent using the N₂ waste stream as a stripping gas. Mostpreferably (but not necessarily), the regeneration of the ultra-leansolvent is performed without heating the CO₂-loaded solvent or flashedCO₂-loaded solvent.

Various objects, features, aspects and advantages of the inventivesubject matter will become more apparent from the following detaileddescription of preferred embodiments, along with the accompanyingdrawing figures in which like numerals represent like components.

BRIEF DESCRIPTION OF THE DRAWINGS

Prior Art FIG. 1 is an exemplary configuration of a modified gasprocessing plant with a revamped amine unit for processing high nitrogenfeed gas.

Prior Art FIG. 2 is another exemplary configuration of a modified gasprocessing plant with an additional amine unit for processing highnitrogen feed gas.

FIG. 3 is an exemplary configuration of a gas processing plant accordingto the inventive subject matter.

DETAILED DESCRIPTION

The inventor has discovered that CO₂ can be effectively removed to verylow levels from a feed gas to an NRU unit by adding a physical solventunit that uses waste nitrogen produced by the NRU as stripping gas toproduce an ultra-lean solvent, which is then used to treat the feed gasto the NRU unit. So treated gas will typically have equal or less than0.001 mol % CO₂ and can be fed to the NRU to produce a pipeline qualitygas. Most typically, the feed gas has a relatively low CO₂ concentration(e.g., 1-2 mol %) and has been subjected to a prior CO2 removal step asdiscussed in more detail below. While contemplated systems and methodscan be employed in a grass roots installation, it should be appreciatedthat the inventive subject matter is particularly advantageous where anexisting CO₂ removal facility does not provide sufficient CO₂ removalcapability for a new or existing downstream NRU. Integration of thephysical solvent unit will provide numerous advantages, including deepCO₂ removal at capital requirement and low cost operation, simplifiedprocess flow, and elimination of an otherwise typically required dryingstep.

In contrast, a typical known gas processing configuration for nitrogenrejection is shown in Prior Art FIG. 1. Feed gas 1, typically at 1000psig to 1500 psig, contains 15-20 mol % N₂ and is treated in amine unit51, producing a treated gas stream 2 with 1-2 mol % CO₂, which isacceptable to avoid CO₂ freezing in the NGL unit. However, if nitrogenrejection is required, the CO₂ content must be further reduced to meetthe CO₂ specification by the downstream NRU 60, typically to 2000 ppmvor lower. The recitation of ranges of values herein is merely intendedto serve as a shorthand method of referring individually to eachseparate value falling within the range. Unless otherwise indicatedherein, each individual value with a range is incorporated into thespecification as if it were individually recited herein. The treated gas2 is dried in molecular sieve drier 52 forming dried stream 3, which isthen processed in NGL recovery unit 53. The NGL recovery 53 unit can bedesigned for either propane recovery or ethane recovery. The NGL unit 53produces an NGL stream 5 and a lean gas stream 4 that is compressed by aresidue gas compressor 54 to a pressure of about 1000 psig to 1500 psigforming stream 6, which is then fed to the NRU 60 that produces a r N₂waste stream 14 that is vented to the atmosphere, and a N₂ depletedstream 17 that is sent to the sales gas pipeline (most pipelinespecifications require the gas to contain no more than 3 mol %nitrogen). As used herein, the term “about” in conjunction with anumeral refers to a range of that numeral starting from 20% below theabsolute of the numeral to 20% above the absolute of the numeral,inclusive. For example, the term “about 100° F.” refers to a range of80° F. to 120° F., inclusive, and the term “about 100 psig” refers to arange of 80 psig to 120 psig, inclusive.

The cold box and fractionation columns (not shown) in the NRU typicallyoperate at very low temperatures, in most cases at −250° F. or lower,which means the residual CO₂ content in the gas stream from aconventional amine unit that is ultimately delivered to the NRU exceedslevels at which CO₂ freezing in the NRU becomes problematic (and rendersthe NRU inoperable). For this reason, amine unit 51 must be revamped fordeeper CO₂ removal. However, this may not be feasible if the amine unitis already operating at it maximum capacity, or will be expensive andthus an economically unattractive solution.

Alternatively, as shown in Prior Art FIG. 2 where like numerals depictlike components as shown in Prior Art FIG. 1, a new amine unit 50 isused to treat the lean gas stream 4 from the NGL recovery unit 53 toreduce its CO₂ content from, typically 1-2 mol % to 2000 ppm or lower,using a more aggressive amine such as DGA or activated MDEA. The treatedgas from the new amine unit 50 is saturated with water and generallyrequires drying in a dehydration unit 55 (e.g., molecular sievedehydration unit) producing a dry gas with CO₂ content that isacceptable to the downstream NRU unit 60. Gas stream 6 is typicallyre-compressed by residue gas compressor 54 prior to entry into the NRU.Unfortunately, the addition of a new amine and dehydration renders suchoption often very costly. With respect to the remaining numerals, thesame considerations for like components with like numerals as providedfor Prior Art FIG. 1 apply.

In contrast, the configurations and methods according to the inventivesubject matter will overcome the difficulties of known configurations ina conceptually simple and elegant manner that allows for implementationin a grass roots facility as well as in a retrofit. More particularly, aphysical solvent unit is fluidly coupled between the amine unit and theNRU that reduces the residual CO2 concentration in the gas stream to alevel acceptable for use in a NRU. In further preferred aspects, thephysical solvent unit receives the gas stream that was previouslysubjected to CO2 removal after compression to a suitable pressure (e.g.,pressure of the NRU or pipeline pressure).

For example, FIG. 3 exemplarily depicts a gas treatment plant fortreatment of a feed gas that comprises CO₂ and N₂. Here, thehydrocarbonaceous feed gas 1 (e.g., from a oil and/or gas productionwell), typically at 1000 psig to 1500 psig, contains 15-20 mol % N₂ andis treated in amine unit 51, producing a treated gas stream 2 with 1-2mol % CO₂, which is acceptable to avoid CO₂ freezing in the NGL unit 53.However, with the feed gas composition of the example, nitrogenrejection is required to meet the CO₂ specification by the downstreamNRU 60 (e.g., in most cases 2000 ppmv or lower). The so treated feed gas2 is dried in molecular sieve drier 52 (or other drying unit, e.g.,glycol dryer) forming dried stream 3, which is then processed in NGLrecovery unit 53. The NGL recovery 53 unit can be designed for propanerecovery and/or ethane recovery as desired and produces an NGL stream 5and a lean gas stream 4. The lean stream 4 is then compressed by residuegas compressor 54 to a pressure of about 1000 psig to 1500 psig formingstream 6, which is then fed to the physical solvent unit that receives aN₂ waste stream from the NRU and that ultimately produces a CO₂-depletedfeed gas, a CO₂-rich flash stream and N₂-rich stripper overhead streamas further described in more detail below.

In the physical solvent unit, gas stream 6 having relatively highnitrogen content is fed to absorber 55 that is configured to receive anultra-lean solvent 7. In especially preferred aspects, the ultra-leansolvent is a physical solvent (preferably propylene carbonate) having avery low residual CO₂ content (typically no more than 0.1 mol %, andeven more typically no more than 0.01 mol %). It should be appreciatedthat among other advantages, a particularly desirable technical effectof using an ultra-lean physical solvent on a previously decarbonizedsolvent (i.e., solvent from which CO₂ was previously removed in aseparate and distinct device) is that the residual CO2 concentration canbe reduced more effectively at increased pressure due to Henry's law.Moreover, use of an ultra-lean solvent allows even further deep CO₂removal, which would not be achievable with a chemical solvent underelevated pressure. Still further, use of an ultra-lean physical solventadvantageously allows regeneration that does not require heating(particularly in combination with a N₂ stripping step) and so eliminatesor reduces greenhouse gas emissions associated with solvent recovery.

Absorber 55 produces a CO₂-depleted feed gas as overhead stream 8containing in some embodiments equal or less than 3,000 ppmv CO₂, inother embodiments equal or less than 2,000 ppmv CO₂, and in yet otherembodiments equal or less than 1,000 ppmv CO₂, as well as a CO₂-loadedsolvent 9 at relatively high pressure that is predominantly determinedby the residue gas compressor 54. The CO₂-loaded solvent 9 is thenletdown in pressure in a hydraulic turbine 56 (or other suitablepressure reduction device) to about 50 psig, and is flashed via stream10 to the separator 57, which produces a CO₂ rich flash stream 11 thatcan be used as a low pressure fuel gas. Flashed solvent stream 12 isfurther letdown in pressure in JT valve 61 forming stream 13, which isfed to solvent stripper 58. The N₂ waste stream 14 from the NRU 60 isused in stripping the flashed solvent stream to produce an ultra-leansolvent 16, which is pumped by pump 59 to about 1000 to 1500 psigforming stream 7 that is re-circulated to the absorber 55.

The CO₂-depleted feed gas 8 from the physical solvent unit is furtherprocessed in the NRU 60, producing a pipeline gas 17 that now meets thepipeline specification (e.g., having equal or less than 3 mol %, andmore preferably equal or less than 2 mol % nitrogen). At least a portionof the rejected nitrogen leaves the NRU 60 as N₂ waste stream 18 that iscompressed by nitrogen blower 62 (e.g., to about 5-50 psig) to formstream 14 which is fed to the physical solvent unit as stripping gas instripper 58. It should be appreciated that the N₂ waste stream can beproduced in the NRU at 5 to 10 psig such that nitrogen blower 62 may notbe required. N₂ stripper 58 uses the N₂ waste stream as stripping gasand produces a N₂ rich striper overhead stream 15 stream that can now bevented to the atmosphere or routed to sequestration.

While all physical solvents (and various non-physical solvents followingHenry's law) are generally contemplated suitable for use herein,especially preferred physical solvents include FLUOR SOLVENT™ (propylenecarbonate), NMP (normal-methyl prrolidone), SELEXOL™ (dimethyl ether ofpolyethylene glycol), and TBP (tributyl phosphate). As already notedabove, physical solvents provide numerous advantages over chemicalsolvents and other CO₂ removing processes (e.g., membrane separation,PSA, etc.) and especially allow increased solubilization of CO₂ atincreased pressure, the capability to remove dissolved CO₂ by flashingwithout the need for steam regeneration. Moreover, where the physicalsolvent is anon-aqueous solvent, the CO₂-depleted feed gas will notrequire a downstream dehydration unit.

Consequently, it is generally preferred that the absorber in thephysical solvent unit will operate at elevated pressure, andcontemplated elevated pressures include 500-700 psig, 700-1,000 psig,1,000-1,500 psig, and even higher. Viewed from another perspective, itis generally preferred that the absorber operates at a pressure that issuitable for feeding the CO₂-depleted feed gas directly into the NRUand/or pipeline without further need of re-compression. Thus, suitablepressures will be at least 700 psig, at least 1,000 psig, at least 1,200psig, at least 1,500 psig, or, even higher, but generally less than3,000 psig. In some aspects, the absorber may even operate atsupercritical pressures. Absorbers for physical solvents to capture CO₂are well known in the art, and all such absorbers are deemed suitablefor use herein.

The so produced CO₂-loaded solvent is preferably reduced in pressure toa pressure that allows flashing of the CO₂ to an remove at least 50%,more preferably at least 70%, even more preferably at least 80%, andmost preferably substantially all (i.e., greater of equal than 90%) ofthe previously dissolved CO₂. Consequently, and depending on theabsorber pressure and pressure reduction, the CO₂-loaded solvent isreduced in pressure in an amount of at least 500 psig, more typically atleast 700 psig, and most typically at least 1,000 psig. Viewed from adifferent perspective, the residual pressure in the flashed solvent willtypically be between 0-50 psig, or between 50 and 100 psig, or between20 and 20 psig.

There are numerous pressure reduction devices known in the art, and allof them are deemed suitable for use herein. However it is especiallypreferred (but not necessary) that the pressure reduction device issuitable to recover at least some energy. For example, suitable pressurereduction devices could be hydraulic turbines to reduce energyconsumption (e.g., via generation of electrical energy, or mechanicalenergy for pumping flashed solvent, etc.). Therefore, it should be notedthat one of the advantages of flashing the physical solvent is thatsignificant quantities of CO₂ can be removed without expenditure of heatenergy while at the same time recovering or generating energy from theexpansion step. Moreover, so flashed solvent is easily separated in aseparator (flash vessel) and further processed while the CO₂-rich flashstream can be routed to an incinerator or sequestration unit. Mosttypically, the CO₂-rich flash stream will comprise at least 50 mol %CO₂, in further embodiments at least 70 mol % CO₂, and in still furtherembodiments at least 90 mol % CO₂, with the remaining components mainlybeing N₂, CH₄, and inert compounds.

In further contemplated aspects of the inventive subject matter, theflashed solvent is then reduced in pressure, most typically to aresidual pressure of between atmospheric pressure (zero psig) and 50psig to allow for stripping with a low-pressure N₂ waste stream from theNRU. In most instances, pressure reduction is performed across aJT-valve, but other pressure reduction devices are also deemed suitablefor use herein. However, it should be noted that the flashed solvent mayalso be subjected to stripping without further pressure reduction(especially where the flashing step already produces a low-pressureflashed solvent). N₂ stripping is in most cases performed in aconventional stripping column that receives the flashed andpressure-reduced solvent, and the nitrogen used for stripping is atleast in part derived from the NRU. Depending on the particular N₂content of the hydrocarbonaceous feed gas, it is contemplated that atleast 10%, at least 30%, at least 50%, at least 70%, or at least 90% ofthe N₂ waste stream from the NRU is used to strip the flashed andpressure reduced solvent. The overhead product of the stripping columnis typically vented to the atmosphere as N₂-rich stripper overheadstream, but may also be further processed (e.g., via PSA, membraneprocess, etc.) or routed to sequestration.

Among other technical advantages it should be recognized that strippingof the flashed solvent with the N₂ waste stream from the NRU not onlyproduces an ultra-lean physical solvent having residual CO2 content of(typically no more than 0.1 mol %, and even more typically no more than0.01 mol %), but also makes effective use of the N₂ waste stream thatwould otherwise be vented to the atmosphere.

Such stripping is in significant contrast to U.S. Pat. No. 6,174,348that teaches use of a chemical solvent, which must be regenerated with asteam reboiler as the solvent is a chemical solvent and as the flashingdoes not effectively removes the CO₂ from the solvent. Moreover, thenitrogen is not provided from within the process (feed gas via the NRU)but obtained from an external air separation unit that must becollocated with the stripper, thereby further adding to the energyinefficiency of this system. Lastly, the '348 system also fails torecover energy from the flashing that could be at least in part used todrive the ultra-lean solvent as described in FIG. 3.

It should also be appreciated that contemplated plants and methods canbe implemented in a grass roots installation or as a retrofit to analready existing acid gas/nitrogen removal unit. With respect to theprimary CO₂ removal unit in contemplated plants and methods it isgenerally contemplated that any type of acid gas removal unit issuitable for use herein (e.g., solvent based, membrane-based, sorbentbased, etc.), however, chemical solvent-based units are particularlypreferred. Therefore, in most aspects of the inventive subject matter,an amine absorber and amine solvent regenerator will be used to reduceCO₂ concentration in the feed gas from >10 mol % to 1-5 mol % CO₂, andmore typically 1-2 mol % CO₂. Secondary CO₂ removal units willpreferably use a physical solvent unit that reduces CO₂ concentrationfrom 1-2 mol % CO₂ to equal or less than 3,000 ppm, equal or less than2,000 ppm, equal or less than 1,000 ppm, and even lower. As notedbefore, it should therefore be appreciated that where the physicalsolvent unit reduces CO₂ by flash and N₂-stripping, an ultra-leansolvent can be produced in a simple and energy efficient manner,particularly where the nitrogen stream is obtained from the same NRUthat is used to reduce the nitrogen concentration of the feed gas.

Consequently, the inventor also contemplates a method of processing afeed gas that includes CO₂ and N₂ in which CO₂ is removed from the feedgas in a primary CO₂ removal unit to a first CO₂ concentration (e.g.,1-5 mol %, or 1-3 mol %, or 1-2 mol %, or 0.5-2 mol %) to so form atreated feed gas, and in which an ultra-lean solvent is used in asecondary CO₂ removal unit to further remove CO₂ from the treated feedgas to so form a CO₂-loaded solvent and a CO₂-depleted feed gas having asecond CO₂ concentration (equal to or less than 3,000 ppmv CO₂, equal toor less than 2,000 ppmv CO₂, equal to or less than 1,000 ppmv CO₂, orbetween 2,000 and 200 ppmv CO₂, or between 2,000 and 500 ppmv CO₂).Nitrogen is then removed from the CO₂-depleted feed gas in a NRU tothereby produce a N₂ waste stream and a pipeline gas, and at least aportion of the N₂ waste stream is used as a stripping gas in thesecondary CO₂ removal unit to thereby produce the ultra-lean solventfrom the CO₂-loaded solvent.

Therefore, in view of the above and attached figures, it should also beappreciated that the inventors contemplate a method of regenerating anultra-lean solvent for deep CO₂ removal of a treated feed gas that hasequal or less than 2 mol % CO₂ in which an ultra-lean physical solventis used in an absorber to remove CO₂ from the treated feed gas tothereby form a CO₂-loaded solvent and a CO₂-depleted feed gas. Nitrogenis then removed from the CO₂-depleted feed gas in a NRU to therebyproduce a N₂ waste stream and a pipeline gas, and the ultra-leanphysical solvent is then regenerated from the CO₂-loaded solvent viaflashing the CO₂-loaded solvent and stripping the flashed CO₂-loadedsolvent using the N₂ waste stream as a stripping gas.

Thus, specific embodiments and applications for the configuration ofacid gas removal unit and nitrogen rejection unit have been disclosed.It should be apparent, however, to those skilled in the art that manymore modifications besides those already described are possible withoutdeparting from the inventive concepts herein. The inventive subjectmatter, therefore, is not to be restricted except in the spirit of thepresent disclosure. Moreover, in interpreting the specification andcontemplated claims, all terms should be interpreted in the broadestpossible manner consistent with the context. In particular, the terms“comprises” and “comprising” should be interpreted as referring toelements, components, or steps in a non-exclusive manner, indicatingthat the referenced elements, components, or steps may be present, orutilized, or combined with other elements, components, or steps that arenot expressly referenced.

What is claimed is:
 1. A method of processing a feed gas that includesCO₂ and N₂, comprising: removing in a primary CO₂ removal unit CO₂ fromthe feed gas to a first CO₂ concentration to thereby form a treated feedgas; using an ultra-lean solvent to further remove CO₂ from the treatedfeed gas to thereby produce a CO₂-loaded solvent and a CO₂-depleted feedgas having a second CO₂ concentration; removing in a nitrogen rejectionunit N₂ from the CO₂-depleted feed gas to thereby produce a N₂ wastestream and a pipeline gas; and using a portion of the N₂ waste stream asa stripping gas to thereby produce the ultra-lean solvent from theCO₂-loaded solvent.
 2. The method of claim 1 wherein the step ofremoving in a primary CO₂ removal unit comprises contacting the feed gaswith an amine solvent.
 3. The method of claim 1 wherein the ultra-leansolvent is a physical solvent.
 4. The method of claim 1 furthercomprising a step of flashing the CO₂-loaded solvent prior to the stepof using the N₂ waste stream as a stripping gas.
 5. The method of claim1 wherein the feed gas is a hydrocarbonaceous feed gas.
 6. The method ofclaim 1 wherein the first CO₂ concentration is between 1-5 mol %, andwherein the second CO₂ concentration equal to or less than 3,000 ppmv.7. The method of claim 1 wherein the first CO₂ concentration is between1-5 mol %, and wherein the second CO₂ concentration equal to or lessthan 1,000 ppmv.
 8. The method of claim 1, wherein the step of using anultra-lean solvent to further remove CO₂ from the treated feed gas isperformed in an absorber of a secondary CO₂ removal unit, and whereinthe step of using a portion of the N₂ waste stream as a stripping gas isperformed in a stripping column of the secondary CO₂ removal unit.